This disclosure relates in general to drilling a wellbore in an earth formation so as to extract hydrocarbons from subterranean reservoirs therein and, more specifically, but not by way of limitation, to testing the hydrocarbons being produced from the subterranean reservoirs during the drilling procedure.
In typical drilling operations, a turntable on the floor of a drilling rig rotates a string of hollow steel pipes, known as drill pipe or drillstring. A drill bit is disposed at the end of the drill pipe and is rotated against the formation at the drill bit face. The drill bit grinds, crushes and chips through the rock as it is rotated by the drill pipe. A drilling fluid, often referred to a drilling mud or mud, is pumped from the surface through the drill pipe to the drill bit, where the drilling fluid flushes the rock cuttings from the drill bit face and lubricates the drill bit. The drilling fluid circulates in the wellbore flowing out through the drill bit and then returning up the annular space between the outside of the drill string and the sidewalls of the wellbore being drilled; this annular space is often referred to as the drilling annulus.
The drilling fluid or mud cools and lubricates the bit, carries the drill cuttings from the hole to the surface and cakes the sidewall of the wellbore to seal the wellbore and prevent the sidewall caving in. The cake formed on the sidewall is often referred to as filter cake. Sealing of the sidewalls is important as it prevents loss of the circulating drilling fluid to the earth formation surrounding the wellbore.
The hydrostatic pressure exerted by the column of drilling fluid in the wellbore prevents blowouts/inflow of reservoir fluids into the wellbore that may result, for example, when the wellbore penetrates a section of the subterranean formation comprising a high pressure oil or gas zone. Such an influx of oil or gas into the wellbore from the reservoir during drilling creates an adverse effect known as a kick, which is a highly undesirable affect that can have many adverse effects to the drilling operation. Thus, in a traditional drilling operation, the weight in pounds per gallon (“ppg”) of the drilling fluid must be sufficiently high to prevent blowouts/kicks, but not high enough to generate a downhole pressure in the wellbore that causes the sidewalls of the formation around the wellbore to fracture resulting in the drilling fluid flowing out of the wellbore through the fractures and into the formation, resulting in drilling fluid loss and break down of the drilling procedure. In other words, if the mud pressure is too low, the formation fluid surrounding the wellbore can force the filter cake from the sidewall of the wellbore and flow into the wellbore, resulting in a blowout/kick. Whereas if the bottomhole pressure produced by the drilling fluid becomes too high, the differential pressure between the wellbore and the surrounding formation becomes great enough that the formation fractures and drilling fluid flows out of the wellbore and into the formation, resulting in lost circulation.
Lost circulation is the loss of drilling fluids to the formation. The loss of drilling mud and cuttings into the formation results in slower drilling rates and plugging of productive formations. When circulation suddenly diminishes, the drilling rate or rate of penetration (“ROP”) must be scaled back as the mud flow rate is reduced. Moreover, losing mud into productive formations can severely damage the formation permeability, lowering production rates therefrom. Such plugged formations must often be subjected to costly enhanced recovery techniques in an effort to restore the formation permeability to raise production rates back up to their former levels.
The drill string usually consists of 30-foot lengths of pipe coupled together. On the lower end of the drill string are heavier-walled lengths of pipe, called drill collars, which help regulate the weight on the bit. When the bit has penetrated the distance of a pipe section, drilling is stopped, the string is pulled up to expose the top joint, a new section of drill pipe is added, the string is lowered into the wellbore and drilling resumes. This process continues until the bit becomes worn out, at which time the entire drill string must be removed from the wellbore. The cost of running a rig for a period of time is extremely high. Therefore, the speed of drilling of the wellbore is extremely important and trips, removing the drill bit from and returning it back into the wellbore, are highly undesirable.
During drilling of the wellbore, steps are taken to keep the pressure at the bottom of the borehole in a pressure window that is not higher than the pressure necessary to fracture the formation, as such fractures will lead to loss of drilling fluids to the formation, and is higher than a pore pressure of the formation to prevent flow of formation fluids into the wellbore as such a influx may create a blowout and/or a kick.
Normally, once a wellbore has been drilled, it is lined or cased with heavy steel piping, called casing or casing string, and the annulus between the wellbore and the casing is filled with cement. Properly designed and cemented casing prevents collapse of the wellbore and protects fresh water aquifers above the oil and gas reservoir from becoming contaminated with oil and gas and the oil reservoir brine. Similarly, the oil and gas reservoir is prevented from becoming invaded by extraneous water from aquifers that penetrated above the productive reservoirs. The total length of casing of uniform outside diameter that is run in the well during a single operation is called a casing string. The casing string is made up of joints of steel pipe that are screwed together to form a continuous string as the casing is extended into the wellbore.
Once the wellbore has been drilled to a target location in the subterranean formation, a location in the earth formation containing an oil/gas reservoir, the wellbore must be prepared for production of the surrounding oil/gas. At this point, the drill bit and drillstring is normally tripped out of the wellbore. If the wellbore is cased with a casing string, the casing string is perforated and pressure at the bottom of the wellbore, may if necessary, be increased to fracture the surrounding formation. At this point, the oil and gas may flow into the wellbore and testing equipment, often deployed on a wireline tool may be disposed into the wellbore to test the properties of the oil/gas flowing into the wellbore so that a production plan can be created and a determination made as to the production properties of the wellbore.